In order to stimulate and more effectively produce hydrocarbons from oil and gas bearing formations, and especially formations with low porosity and/or low permeability, induced fracturing (called “frac operations”, “hydraulic fracturing”, or simply “fracing”) of the hydrocarbon-bearing formations has been a commonly used technique. In a typical hydraulic fracturing operation, fluid slurries are pumped downhole under high pressure, causing the formations to fracture around the borehole, creating high permeability conduits that promote the flow of the hydrocarbons into the borehole. These frac operations can be conducted in vertical, horizontal or deviated boreholes, and in either intervals of uncased wells, or in cased wells through perforations.
In cased boreholes in vertical wells, for example, the high pressure fluids exit the borehole via perforations through the casing and surrounding cement, and cause the oil and gas formations to fracture, usually in thin, generally vertical sheet-like fractures in the deeper formations in which oil and gas are commonly found. These induced fractures generally extend laterally a considerable distance out from the wellbore into the surrounding formations, and extend vertically until the fracture reaches a formation that is not easily fractured above and/or below the desired frac interval. The directions of maximum and minimum horizontal stress within the formation determine the azimuthal orientation of the induced fractures.
The high pressure frac fluids typically contain particulate materials called proppant. Proppant is generally composed of sand, resin-coated sand or ceramic particles, and the fluid used to pump the proppant downhole is typically designed to be sufficiently viscous to assist in entraining the proppant particles in the fluid as it moves downhole and out into the induced fractures.
After the proppant has been placed in the fracture and the fluid pressure relaxed, the fracture is prevented from completely closing by the presence of the proppants which thus provide a high conductivity flow path to the wellbore which results in improved production performance from the stimulated well.
When the fracture closes, a compressive “closure” stress (often exceeding 10,000 psi) is placed on the proppant. At closures stresses exceeding about 5,000 psi, sand and resin-coated sand proppants lose much of their ability to provide a conductive conduit in the fracture for formation fluids. The sand grains fail or are crushed under these stresses resulting in the generation of fines and a consequent reduction of porosity and permeability within the fracture. Resin-coating of the sand can reduce the generation of fines and extend the utility of sands to some degree. Ceramic proppants are much stronger than sands and resin-coated sands, however, and can provide much greater conductivity in the fracture at all closure stresses. Consequently, ceramic proppants are often used to provide much greater conductivity in the created fracture to improve the production rates and hydrocarbon recoveries.
Ceramic proppants may be manufactured from a variety of starting raw materials which, along with the manufacturing process employed, will define the performance characteristics of the proppant. FIG. 1 shows comparisons of the permeability of three types of common ceramic proppants: a lightweight proppant, an intermediate density proppant and a high density proppant. These proppants differ primarily due to the composition of the starting raw materials from which they are made. In the case of lightweight ceramic proppant, the starting raw material is typically kaolin clay containing approximately 50% alumina oxide (Al2O3). The starting raw material for an intermediate density ceramic proppant is typically a bauxitic clay containing about 75% alumina oxide and the starting raw material for a high density ceramic proppant is also typically a bauxitic clay but with an alumina oxide content of about 85%. The differences in alumina content of the starting raw materials lead to differences in the final crystalline structure of the sintered ceramic proppant and thus differences in the mechanical properties of the three types of ceramic proppants. These comparisons assume somewhat similar processing characteristics. Proppant of similar alumina content may vary in performance due to variability in the quality of the processing. Further, a combination of higher alumina content with improved processing may lead to even higher conductivities.
For many oil and gas wells the composition of the fluids produced which include hydrocarbons, hydraulic fracturing fluids, and formation waters is such that it is beneficial to add to the fluids a chemical treatment agent to inhibit deleterious properties which the fluids might otherwise exhibit.
Typical chemical treatment agents provide some function that is useful for the production performance of a hydraulically fractured well. For example, the produced fluids may be corrosive to the well casing so a corrosion inhibitor may be added to the fracturing fluid or subsequently pumped into the producing formation in a “squeeze operation”. In another example, paraffin or wax control is desirable to control the deposition of higher molecular weight hydrocarbons in an oil and gas stream.
The deposition of paraffin or wax inhibits flow, and if it occurs downhole can reduce well production by “choking off” the well in the area of deposition. The effectiveness of wax inhibitors is generally measured using techniques that report pour point or pour point depression, which is the temperature at which a particular crude oil sample is “pourable” by standard measurement techniques. Another commonly used test method is the “wax appearance temperature” which uses an optical technique to determine the temperature at which wax or wax crystals first appear. By either of these test methods, a lowering of the measured temperature is the objective of the paraffin or wax inhibitor. Paraffin inhibitors are typically classified by function. Those inhibitors that affect the wax appearance temperature are usually referred to as wax inhibitors or wax crystal modifiers. Those inhibitors that affect the pour point are referred to as pour point depressors (PPD) or flow improvers. There is significant overlap in the structure and function of these two types of inhibitors and suitable inhibitors generally include ethylene polymers and copolymers, combination polymers, and branched polymers with long alkyl chains.
Many other types of chemical treatment agents may also be used in the prevention of various deleterious reactions that may occur in oil and gas wells including scale inhibitors, hydrate inhibitors, asphaltene inhibitors and other organic deposition inhibitors, biocides, demulsifiers and other oilfield treatment chemicals.
One technique for delivering such chemical treatment agents downhole includes infusing porous ceramic proppant particulates with the chemical treat agent. As described in U.S. Pat. No. 5,964,291 and U.S. Pat. No. 7,598,209, the fraction of chemically infused proppant added to standard proppant in a hydraulic fracturing operation is determined by the amount of the chemical treatment agent that is desired to be incorporated in the fracturing operation. This in turn is a function of the porosity of the porous ceramic proppant particulates and the degree to which the chemical treatment agent can be placed in the pore spaces of the porous ceramic proppant particulates.
U.S. Pat. No. 5,964,291 discloses that porous ceramic proppants may be sufficiently strong to be used on their own or in conjunction with particles of non-porous materials. However the changes in conductivity of the propped fracture resulting from the use of the porous ceramic proppant as compared to standard proppant is not disclosed. It is further disclosed that the porous particles should comply with API specifications for crush resistance but again the relationship to conductivity impairment is not disclosed. No method for mitigating conductivity impairment should it occur is disclosed.
U.S. Pat. No. 7,598,209 similarly discloses that porous proppants may be sufficiently strong to be used on their own or in conjunction with particles of non-porous materials again without disclosure of the effects on conductivity. It is further disclosed that the porous particulate may be any porous ceramic particulate that has requisite physical properties such as desired strength to fit particular downhole conditions but no disclosure of what this means is offered. U.S. Pat. No. 7,598,209 offers one example of conductivity impairment in which the conductivity and permeability of a typical frac sand—a 20/40 mesh Ottawa—is compared to a 20/40 mesh Ottawa sand containing 10% of a ceramic proppant with 12% porosity that has been chemically infused. The data presented show a conductivity reduction of 8%, 20% and 24% at 2 k, 4 k and 6 k psi closure stress respectively when the porous ceramic is added to the Ottawa sand.
In many instances, the chemical treatment agent must first be dissolved in an aqueous, organic or inorganic solvent to enable the infusion of the chemical treatment agent into the porous ceramic proppant particulates. If the chemical treatment agent is too viscous, however, this can result in lower effective amounts of the chemical treatment agent being present in the infused proppant than desired or uneven or ineffective infusion altogether. Dissolving the chemical treatment agent in the solvent is also an additional step that can be costly and time consuming. It would therefore be beneficial to infuse a chemical treatment agent directly into porous ceramic proppant particulates without the need for a solvent.
Tracers have been used in connection with hydraulic fracturing, to provide certain types of diagnostic information about the location and orientation of the fracture. For example, U.S. Pat. No. 3,987,850 and U.S. Pat. No. 3,796,883 describe the use of radio-active tracers to monitor the functioning of a well gravel pack. Tracers for hydraulic fracturing have been associated with various carrier materials as particles from which the tracer itself is released after placement in the created hydraulic fracture. U.S. Pat. No. 6,723,683 discloses starch particles as a carrier for a variety of oilfield chemicals including tracers. U.S. Patent Application Publication No. 2010/0307745 discloses the use of tracer particles in conjunction with hydraulic fracturing in which the tracer particles are composed of a tracer substance and a carrier wherein the carrier is comprised of starch or polymeric materials.
Carriers such as starch or polymeric materials are weak materials which if added to standard proppant, and particularly a ceramic proppant, in a hydraulic fracture can negatively affect conductivity. Further, the densities of starch or polymeric carrier materials are not similar to proppants typically used in hydraulic fracturing resulting in density segregation which can lead to non-uniform distribution of the tracer chemicals in the created fracture.
Tracers incorporated into hydraulic fracturing operations can provide information to operators which can enable them to improve completion and stimulation programs. This is accomplished by placing one or more unique tracers in various portions of the fracturing operation, such as in different stages if multiple fracturing stages are performed in the well or in different portions of a stage. Analysis of the produced fluids for the presence of the tracers can provide diagnostic information as to which stages or portions of a stage are in contact with the produced fluids. Tracers which differentially partition into the hydrocarbon or water phases can provide further diagnostic data regarding the relative hydrocarbon to water ratio of the produced fluids from a stage.
Nanoparticle dispersions and surfactants have been used in connection with hydraulic fracturing to provide improved fluid production from a well. For example, U.S. Patent Publication No. 2010/0096139 describes the use of a fluid mixture of nanoparticles and a wetting agent that is injected or pumped into a well to enhance the wetting characteristics of the formation surfaces. Similarly, U.S. Pat. No. 7,380,606 describes the use of a solvent-surfactant blend that is injected or pumped into a subterranean formation to improve fluid recovery.
The wetting characteristics, or wettability, of a solid surface is defined as the preference of the solid surface to come into contact with the wetting phase, i.e., a liquid, such as water or oil, or a gas. Wettability has an impact on qualities such as permeability and conductivity. For example, a water-wet formation or proppant surface—one that exhibits a preference for coming into contact with water as opposed to a hydrocarbon—may lead to decreased hydrocarbon permeability and therefore decreased hydrocarbon recovery. Other chemical treatment agents such as surfactants and nanoparticle dispersions, however, may be introduced into a fracture to alter the wetting characteristics of the fracture environment to improve the desired permeability and recovery.
For non-porous, solid surfaces such as a formation surface, the wetting phase will spread across the surface. For porous, solid surfaces, such as porous ceramic proppant, the wetting phase may be absorbed by the surface. Pumping fluids containing nanoparticle dispersions or surfactants into a formation in liquid form may improve the wettability of a formation surface, but may not provide any significant or long-term improvement in the wetting characteristics of the proppant, and therefore would not offer the corresponding improvement in proppant conductivity that promotes hydrocarbon production, reservoir water production, or frac fluid clean up or production.
In the case of a horizontal well, as many as 40 separate hydraulic fracturing operations, or stages, may be conducted. It may sometimes be desirable to utilize unique tracers in each of these stages and further to determine the relative amounts of hydrocarbons and water production from each of the stages. In addition, one may wish to determine the relative fluid production from different portions of each of the 40 stages. It is also desirable for the tracers to be released over an extended period of time of perhaps months or years. In such a scenario, more than 100 unique tracers would be required. Further, to be cost effective the amount of each tracer required should ideally be limited. Tracers in the prior art are limited in number and could not accomplish this task. Additionally, many of the prior art tracers cannot preferentially partition into the hydrocarbon or water phases and detection limits are too high for long term identification especially when placed directly in the frac fluid.
Therefore, what is needed is a method to add porous chemically infused ceramic proppant to standard non-porous proppant in a manner that will not negatively impair proppant conductivity. Also, what is needed is a tracer carrier that does not segregate from the standard proppant when added in a hydraulic fracture and that does not negatively impact conductivity. Additionally, what is needed is a method of altering wettability of a proppant through the infusion of nanoparticle dispersions or surfactants into the porous proppant to increase fluid production.
Also, it would be beneficial to have a tracer technology that can provide a very large number of unique tracers that are capable of partitioning into either of the hydrocarbon or water phases as desired, are detectable at very low concentrations in the produced fluids for an extended period of time, and are not subject to degradation at the high temperatures and pressures often found in well formations.
Additionally, in many well operations, the release of the chemical treatment agent over an extended period of time is desirable. What is needed is a porous ceramic proppant infused with a chemical treatment agent and a method of introducing the proppant into a fracture such that the release of the chemical treatment agent into the fracture or well area can be controlled over an extended period of time. Also, what is needed is a semi-permeable coating for the proppant that is substantially non-degradable in the presence of the well fluids but permits diffusion of the chemical treatment agent through the semi-permeable coating so as to release the chemical treatment agent into the fracture or well area over an extended period of time.